Method to attenuate acid reactivity of subterranean formations with omniphobic chemicals

ABSTRACT

A formation treatment composition that includes an aqueous fluid, at least omniphobic fluorochemical, and an acid is described. A method of attenuating acid reactivity of a formation rock is also described. The method includes injecting a formation treatment composition into a reservoir, contacting the omniphobic fluorochemical of the formation treatment composition with the rock, and mitigating a reaction between the acid of the formation treatment composition and the rock surface.

BACKGROUND

In order to increase hydrocarbon production in carbonate formations,treatments are often performed with acids, such as inorganic acids andorganic acids. These acids may be selected based on their reactivitywith the carbonate formations of rock matrix. Matrix stimulationtreatments may be performed by injecting these acids through wellboresto react with and dissolve parts of the carbonate formations. Insuccessful treatments, the dissolution process results in the formationof highly conductive channel networks, thereby enhancing hydrocarbonproduction. Such acid stimulation may be carried out in carbonateformations (e.g., calcite, dolomite, and the like) using strong mineralacids. For example, hydrochloric acid (HCl) may be chosen for its lowcost and effectiveness in dissolving calcium and magnesium carbonates.Moreover, the reaction products resulting from the dissolution arereadily soluble in water, which may be advantageous in preventing damageof the formation.

However, HCl may react intensely with calcite-rich rock matrices,particularly at elevated temperatures, resulting in significantoperational limitations in terms of performance or cost. For example,when HCl is used in high concentrations, it may react rapidly with therock matrix before deep penetration into the rock matrix can beachieved. This will pose the need for larger volumes of acid to be usedto efficiently stimulate the zone. Other limitations may include varioussafety concerns associated with the transfer and handling of highlycorrosive acids at the well site. As well, undesired acid reactionsoccurring near the wellbore may cause corrosion and damage to drillingequipment, metal tubulars, and casing, resulting in safety issues foroperators. Additionally, corrosion inhibitors may be needed for the acidtreatment, increasing the cost and complexity of operations. Corrosioninhibitors may also lead to formation damage which, if not addressed,may reduce permeability in the reservoir thereby limiting hydrocarbonproduction.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, embodiments disclosed herein relate to a formationtreatment composition that includes an aqueous fluid, at leastomniphobic fluorochemical, and an acid.

In another aspect, embodiments disclosed herein relate to a method ofattenuating acid reactivity of a formation rock. The method includesinjecting a formation treatment composition into a reservoir. Theformation treatment composition includes a solution of a fluid thatincludes at least one omniphobic fluorochemical and an acid. The methodalso includes contacting the omniphobic fluorochemical of the formationtreatment composition with the rock, thereby creating an omniphobicfluorochemical barrier on a surface of the formation rock, andmitigating a reaction between the acid of the formation treatmentcomposition and the rock surface, thereby attenuating a reaction betweenthe rock and the acid.

In another aspect, embodiments disclosed herein relate to a method ofattenuating acid reactivity of a formation rock, where the methodincludes injecting a pre-flush fluid into a reservoir. The pre-flushfluid includes a solution including an omniphobic fluorochemical. Themethod also includes contacting the omniphobic fluorochemical of thepre-flush fluid with a rock surface of the formation, thereby creatingan omniphobic fluorochemical barrier on the rock surface with theomniphobic fluorochemical of the pre-flush fluid, injecting an acidicfluid into the reservoir, where the acidic fluid comprises an acid in anaqueous fluid, and mitigating a reaction between the acid of the acidicfluid and the rock surface, thereby attenuating a reaction between therock and the acid.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a graph demonstrating results obtained for water contact anglemeasurements at varying concentrations in accordance with one or moreembodiments.

FIG. 2 is a graph of pressure measurement results across a core samplemeasured during acid injection in accordance with one or moreembodiments.

DETAILED DESCRIPTION

Several strategies have been employed for retarding the reaction ratebetween an acid and a rock matrix. For example, the acid may beencapsulated or emulsified to form a temporary barrier between the acidand the rock matrix. The temporary barrier may be formed by apolymer-type shell or coating, an acid-in-diesel (a water-in-oil)emulsion, foaming of the acid, or gelled systems. When the acid isencapsulated or emulsified, stimuli changes, such as temperature,pressure, pH, or shear, may be used to trigger the release of the acid.Alternative strategies have included the use of organic acids, chelants,or retarding agents. However, limitations still exist, such as the highfriction pressures resulting from pumping of emulsified acid systems andincreased operational complexity in fluid preparation. The solubility ofthe resultant products of organic acids with the matrix material mayalso be limited. The reaction rate between the acid and the rock matrixmay also be attenuated by an acid retarding agent containing a saltwhich has the potential to slow down proton diffusion from the bulk acidto the rock surface.

There exists a need for improved matrix acid stimulation and acidfracturing of carbonate rich reservoirs to achieve a deeper penetrationof acid and to minimize the amount of acid used. Accordingly,improvements are needed, for instance to achieve deeper penetration ofacid into a reservoir, or to minimize the amount of acid used, or both.This invention provides a method for controlling and reducing thereaction rate between hydrochloric acid (HCl) and the carbonate rockmatrix through the addition of at least one omniphobic fluorinatedcompound that may be zwitterionic, anionic, cationic or neutral innature.

One or more embodiments of the present disclosure relate to a formationtreatment composition for retarding the reaction rate between an acid(e.g. HCl) and carbonate formations of the rock matrix, carbonatereservoirs, and/or carbonate-based damaged areas of sandstonereservoirs. In one or more embodiments, the formation treatmentcomposition may include an omniphobic compound and an acid. Theomniphobic compound may be a fluorinated compound, such as a fluorinatedsurfactant, a fluorinated polymer, or combinations thereof. The term“omniphobic compound” used throughout the specification refers to acompound that repels any liquid, such as hydrocarbon solvents andaqueous solutions.

Fluorochemicals, e.g., fluoropolymers, fluorinated surfactants, andfluorinated polymeric surfactants, have good thermal, chemical,photochemical, hydrolytic, oxidative, and biological stability. Thisstability is due to the strength of the carbon-fluorine bond, one of thestrongest in organic chemistry. The strength of the carbon-fluorine bondis a result of the electronegativity of fluorine atom, which impartspartial ionic character of the carbon and fluorine atoms, and therefore,shortens the carbon-fluorine bond length and strengthens the bondthrough favorable covalent interactions.

Additionally, multiple carbon-fluorine bonds increase the strength andstability of other nearby carbon-fluorine bonds on the same geminalcarbon, as the carbon atom has an increased partial positive charge.Furthermore, multiple carbon-fluorine bonds also strengthen the“skeletal” carbon-carbon bonds from the inductive effect. Therefore,saturated fluorocarbons are more chemically and thermally stable thantheir corresponding hydrocarbon counterparts, and indeed any otherorganic compound. Fluorochemicals, and in particular fluoropolymers, areused in a great variety of applications due to excellent physicochemicalproperties such as chemical and thermal stability, hydrophobicity,omniphobicity, low surface energy, and environmental resistance.

Formation Treatment Composition

The formation treatment composition of one or more embodiments mayinclude an solvent, a fluorochemical, and an acid.

The fluorochemical may be an omniphobic fluorochemical. In someembodiments, the omniphobic fluorochemical may be nonionic,zwitterionic, anionic, or cationic. The omniphobic fluorochemical may beselected from the group consisting of a nonionic acrylic fluorinatedcopolymer, a nonionic fluorinated surfactant, partially fluorinatedacrylic copolymer, a nonionic fluorinated methacrylate polymer, ananionic phosphate fluorinated surfactant, an anionic sulfate fluorinatedsurfactant, and combinations thereof.

In one or more particular embodiments, the omniphobic fluorochemical maybe water-soluble. The omniphobic fluorochemical of one or moreembodiments can be linear, branched chain, dendritic molecules, orpolymer brushes. The term “polymer brushes” may be defined as denselayers of polymer chains grafted to a primary polymer chain, where thedistance between grafts is less than the dimensions of the boundpolymer. Dendritic molecules include molecules with high symmetrysurrounding a core structure and usually exhibit a radial shape. Theomniphobic fluorochemicals can include alkyl, aryl or substituted alkyand aryl derivatives.

In such embodiments, the omniphobic fluorochemical may include ahydrophilic head-group and a hydrophobic tail. The hydrophilic headgroup has a chemical affinity/retention towards the rock surface. Thehydrophobic tail may include a long chain of alkyl groups. One or moreof the alkyl groups are fluorinated. The fluorinated alkyl groups mayrepel water or aqueous solutions, such as acidic solutions, as well asoleic phases, such as condensate or crude oil, from the rock surfacethus creating a temporary barrier to delay acid reactivity.

Notably, the functionality of the omniphobic fluorochemical can betailored to increase adsorption and retention to the rock surface inaddition to degree of repellency to best meet the application needs. Insome embodiments, the omniphobic fluorochemical may be functionalized topromote stronger interaction with the rock matrix, for example, byintroducing a greater number of hydrophilic moieties on the omniphobicfluorochemical molecule or by introducing functional moieties that willimpart ionic, covalent, non-covalent interactions, or combinationsthereof with neighboring surfactant molecules adsorbed on the formationsurface (for example, a greater number of carbon-fluorine bonds, pi-pistacking, and hydrogen bonding). The resulting more compact stacking ofneighboring surfactant molecules on the formation surface may provide amore effective barrier to water and aqueous solutions containing acid,enhancing the attenuation effect.

General formulas of omniphobic fluorochemicals in accordance with thepresent disclosure are represented by Formula (I) and Formula (II),described below.R_(f)—SO₂N⁻—R_(x)·M⁺  Formula (1)

where R_(f) is a C₁ to C₁₂ perfluoroalkyl group, R_(x) is hydrogen, analkyl group, a hydroxyalkyl group, an alkylamine oxide, analkylcarboxylate group or an aminoalkyl group, and M⁺ is a cation. Thecation M⁺ may be selected from the group consisting of ammonium,phosphonium, alkali metal cations, such as lithium, potassium, orsodium, other metal cations, and combinations thereof. Thefluoro-containing pendant group (R_(f)) can be bonded to a primary,secondary or tertiary carbon.R_(f)-Q-R_(y)—SO₃ ⁻·M⁺  Formula (II)

where R_(f) is as described above with regard to Formula (I), R_(y) isan alkylene of the formula —C_(n)H_(2n)(CHOH)_(o)C_(m)H_(2m)—, where nand m are independently 1 to 6, and o is 0 or 1, and M⁺ is a cation. Thecation M⁺ is as described above with regard to Formula (I). Q is —O—, or—SO₂NR₂—, where R₂ is an H—, an alkyl, an aryl, a hydroxyalkyl, aaminoalkyl, or a sulfonatoalkyl group.

In one or more particular embodiments, Formula (I) may be a compoundhaving the structure as shown in Formula (III). As mentioned above, thecation M⁺ may be a sodium cation, a potassium cation, an ammoniumcation, or a phosphonium cation.

Embodiments in which the fluorochemical has a general structure as shownin Formula (II), the fluorochemical may be as shown as Formula (III).

In one or more embodiments, the fluorochemical may be nonionic. Thefluorochemical may be a nonionic acrylic fluorinated copolymer, anonionic fluorinated surfactant, partially fluorinated acryliccopolymer, or a nonionic fluorinated methacrylate polymer. In one ormore particular embodiments, the fluorochemical may have a structureselected from the group consisting of Formulas (IV) to (VI).

where s, u, t, v, and w are independently between 5 and 150. As shown inFormula (IV), R₂ is a C₁ to C₁₂ perfluoroalkyl group, and R₁ ishydrogen, an alkyl group, a hydroxyalkyl group, an alkylamine oxide, analkylcarboxylate group or an aminoalkyl group. As shown in Formula (VI),X is a neutral end group, such as a hydroxy group or a sulfonamide.

Non-limiting examples of Formula IV include alkanamide,perfluoro-N-(14-hydroxy-3,6,9,12-tetra oxatetradec-1-yl) andpoly(oxy-1,2-ethanediyl),α-(perfluoro-1,4,7,10-tetramethyl-13-oxo3,6,9,12-tetraoxaeicos-1-yl)-ω-hydroxy.A non-limiting example of Formula V includes a copolymer oftetrafluoroethylene and trifluoro methane vinyl ether. Non-limitingexamples of Formula VI include (per)fluorinated organic surfactants,such as perfluorooctane sulfonic acid (1-Octanesulfonic acid,heptadecafluoro-, 3M), perfluorooctane sulfonate lithium,perfluorooctane sulfonate potassium, perfluorooctane sulfonate ammonium,perfluorooctanoic acid (perfluoroheptanecarboxylic acid, available from3M), and polymers that may include perfluorooctane sulfonic acid and/orsalts derived thereof.

Examples of commercially available fluorochemicals in accordance withthe present disclosure include, but are not limited to, NW100®Fluorinated Surfactant in water (Verdechem, Canada), WS1200® (3M,Minnesota), Zonyl® UR (Chemours, Delaware), Zonyl® TBS (Chemours,Delaware), Dynasylan® F 8815 (Evonik Industries, New Jersey), Dynasylan®F 8263 (Evonik Industries, New Jersey), and Dynasylan® F 9896 (EvonikIndustries, New Jersey) may be included in the formation treatmentcomposition.\

In one or more particular embodiments, the omniphobic fluorochemical maybe a fluorinated amphiphilic block copolymer having two blocks. Thefluorinated amphiphilic block copolymer may have a first block bearingthe head moiety that adsorbs onto the formation surface and a secondblock bearing the fluorinated tail moiety that repels theacid-containing aqueous phase from the formation surface, providing atemporary barrier between the acid and the carbonate rock matrix. Thefirst block is hydrophilic with preferential affinity toward theformation surface and may be anionic, cationic, or polar uncharged. Thesecond block may be a hydrophobic block with fluorinated groups.

In one or more embodiments, an omniphobic block copolymer may be acompound represented by Formula (VII), including a first block (i.e.Block 1) and a second block (i.e. Block 2). In some embodiments, theamphiphilic block copolymer may have more than two blocks.

where n and p independently selected and range from 5 to 150. In someembodiments, R₃, R₄, X_(1,) and X₂ may independently be a halogen,hydrogen, cyano group, straight or branched alkyl of C₁-C₂₀, straight orbranched perfluoroalkyl of C₁-C₂₀, α, β-unsaturated straight or branchedalkenyl or alkynyl of C₂-C₁₀, α, β-unsaturated straight or branchedalkenyl of C₂-C₆ substituted with a halogen, C₃-C₈ cycloalkyl,heterocyclyl C(═Y)R₅, C(═Y)NR₆R₇, or YC(═Y)R₈ (where Y may be NR₈ or Oand R₅ is alkyl of C₁-C₂₀, alkoxy of C₁-C₂₀, aryloxy or heterocyclyloxy;R₆ and R₇ are independently H or alkyl of C₁-C₂₀, or R₆ and R₇ may bejoined together to form an alkylene group of C₂-C₅, thus forming a 3- to6-membered ring; and R₈ is H, straight or branched C₁-C₂₀ alkyl oraryl). In some embodiments, X₁ and X₂ may independently be hydrogen,hydroxy, or an alkoxy group.

Block one may be derived from a first monomer, and block two may bederived from a second monomer. In one or more particular embodiments,the first monomer, the second monomer, or both may contain at least onefluorinated alkyl group. The first monomer may be acrylic acid,2-acrylamido-2-methylpropanesulfonic acid, 2-hydroxyethyl acrylate,acrylamide, N,N′-dimethylacrylamide, and 2-(dimethylamino)ethylmethacrylate.

In one or more embodiments, the first monomer may be an anionic or acationic monomer. In such embodiments, the first monomer may be derivedfrom methacrylate or methacrylamide monomers with carboxylic acid orcarboxyl groups, for example, acrylic acid, methacrylic acid, ethacrylicacid, α-chloroacrylic acid, crotonic acid, maleic acid, itaconic acid,citraconic acid, mesaconic acid, glutaconic acid, aconitic acid, fumaricacid, and monoethylenically unsaturated C₄-C₁₀ (preferably C₄ to C₆)dicarboxylic acid monoesters (e.g., monomethyl maleate). In someembodiments, the first monomer may be derived from methacrylate ormethacrylamide monomers with phosphate, phosphonate, or phosphonitegroups in free acid form or in saline form, for example,2-acrylamido-ethylphosphonic acid (AEPA), monoacryloyloxyethylphosphate, bis(2-methacryloyloxyethyl) phosphate, vinylphosphonic acid,allylphosphonic acid, isopropylphosphonic acid, diallyl aminomethylenephosphonate, and salts of above acids.

In some embodiments, the first monomer may be derived from a monomerwith sulfonic acid or sulfonate groups, for example, 3-sulfopropylmethacrylate, 2-propene-1-sulfonic acid, sodium 1-allyloxy-2hydroxypropyl sulfonate (COPS 1), 2-acrylamido-2-methylpropanesulfonicacid (AMPS), methallyl sulfonate, sodium vinylsulfonate, and sodiumstyrenesulfonate. In some embodiments, the first monomer may be derivedfrom methacrylate or methacrylamide monomers with ammonium groups, forexample, N,N′-dimethylaminomethyl meth acrylate, N,N′-dimethylaminoethylmethacrylate, N,N′-diethylaminoethyl methacrylate,N,N′-dimethylaminopropyl methacrylate, N,N′-diethylaminopropylmethacrylate, N,N′-dimethylaminocyclohexyl methacrylate,N-[2-(dimethylamino) ethyl] methacrylamide, N-[3-(dimethylamino) propyl]methacrylamide, N-[4-(dimethylamino) butyl] methacrylamide,N-[2-(diethylamino) ethyl] methacrylamide, and N-[4-(dimethylamino)cyclohexyl] methacrylamide, and [2-(methacryloyloxy) ethyl]trimethylammonium chloride.

In some embodiments, the first monomer may be zwitterionic, for example,N-(3-sulfopropyl)-N-methacroyloxyethyl-N,N′-dimethylammonium betaine,N-(3-sulfopropyl)-N-methacroylamidepropyl-N,N′-dimethylammonium betaine,N-(3-carboxymethyl)-N-methacroylamidepropyl-N,N′-dimethylammoniumbetaine, and N-carboxymethyl-N-methacroyloxyethyl-N,N′-dimethylammoniumbetaine.

The first monomer may be derived from polar uncharged monomers. In someembodiments, the first monomer may be derived from methacrylate ormethacrylamide monomers with C₂-C₃₀ alkane diols or polyethylene glycol,for example, 2-hydroxyethyl methacrylate, 2-hydroxypropyl methacrylate,3-hydroxypropyl methacrylate, 3-hydroxybutyl methacrylate,4-hydroxybutyl methacrylate, 6-hydroxy hexyl methacrylate,3-hydroxy-2-ethylhexyl methacrylate, 2-hydroxy-3-phenoxypropylmethacrylate, N-(hydroxymethyl) acrylamide, N-(2-hydroxypropyl)methacrylamide, N-hydroxyethylacrylamide, N-[tris (hydroxymethyl)methacrylamide, glycerol acrylate, glycerol monomethacrylate,4-vinylphenylboronic acid, and vinyl boronic acid pinacol ester. In someembodiments, the first monomer may be derived from acrylamide monomers,for example, N,N′-(dimethyl acrylamide) (DMA), morpholine N-oxideacrylamide, diacetone acrylamide, N,N′-dimethyl methacrylamide,N,N′-diethylacrylamide, N-isopropyl methacrylamide, N-tert-butylmethacrylamide, and diacetone acrylamide. In some embodiments, the firstmonomer may be derived from other hydrophilic monomers, for example,4-acryloylmorpholine, 2-N-morpholinoethyl methacrylate, methacrylate ofpolyethylene glycol, methacrylate of diethylene glycol, ethylene glycolmethyl ether methacrylate, poly (propylene glycol) acrylate,2-chloroethyl methacrylate, tetrahydrofurfuryl acrylate, vinylacetamide, vinyl pyrrolidone, N-vinyl piperidone, N-vinyl caprolactam,N-vinyl-5-methyl-2-pyrrolidone, N-vinyl-5-ethyl-2-pyrrolidone,N-vinyl-6-methyl-2-piperidone, N-vinyl-6-ethyl-2-piperidone,N-vinyl-7-methyl-2-caprolactam, and N-vinyl-7-ethyl-2-caprolactam.

As mentioned above, Block 2 may be derived from a second monomer. Thesecond monomer may include one or more of fluorinated monomers of methylacrylate, tert-butyl acrylate, butyl acrylate, 2-ethylhexyl acrylate,dodecyl acrylate, stearyl acrylate, and styrene. In some embodiments,the second monomer may be a hydrophobic fluorinated alkyl methacrylatemonomer, fluorinated C₂-C₄₀ alkyl esters of acrylic acid, fluorinatedC₁-C₄₀ alkyl esters of methacrylic acid, and fluorinated vinylaromatics. In some embodiments, the second monomer may be alkylmethacrylate monomers with fluorinated C₁-C₂₀ alkyl chains, fluorinatedC₂-C₄₀-alkyl esters of acrylic acid, fluorinated C₁-C₄₀ alkyl esters ofmethacrylic acid. In some embodiments, the second monomer may includeone or more fluorinated monomers of methyl methacrylate, ethylmethacrylate, N-propyl methacrylate, isopropyl methacrylate, N-butylmethacrylate, isobutyl methacrylate, tert-butyl methacrylate, pentylmethacrylate, N-hexyl methacrylate, N-heptyl methacrylate, N-octylmethacrylate, 2-ethylhexyl methacrylate, decyl methacrylate, laurylmethacrylate, palmityl methacrylate, stearyl methacrylate, hydrenolmethacrylate, behenyl methacrylate, polyisobutene methacrylate,phenoxyethyl methacrylate, phenyl methacrylate, benzyl methacrylate,vinyl aromatic monomers (e.g., styrene), N-vinylcarbazole,2-vinylpyridine, 4-vinylpyridine, 2-vinylpyrazine, 1-vinylimidazole,4-acetoxystyrene, 4-bromostyrene, 2,4-dimethylstyrene,2,5-dimethylstyrene, 3,5-dimethylstyrene, 4-ethoxystyrene,4-tert-butylstyrene, 2-chlorostyrene, 3-chlorostyrene, 4-chlorostyrene,4-ethoxystyrene, 4-fluorostyrene, 2,6-dichlorostyrene, 4-methoxystyrene,methylstyrene, 3-methylstyrene, 4-methylstyrene, 2,4,6-trimethylstyrene,and acrylate or methacrylate monomers with fluorinated functionality.

As noted above, the formation treatment in accordance with one or moreembodiments includes a fluorochemical as described above, an aqueoussolvent and an acid. The fluorochemical may be present in the formationtreatment composition at a concentration of less than 100 gpt (gallonsper 1000 gallons). In particular embodiments, the fluorochemical may bepresent in the treatment composition in an amount having a lower limitof one of 0.1 wt % (weight percent), 0.5 wt %, 1.0 wt %, 2.5 wt %, 5 wt%, and 7.5 wt % and an upper limit of one of 2.5 wt %, 5 wt %, 7.5 wt %,8 wt %, 9 wt %, 9.5 wt %, and 10 wt %, where any lower limit may bepaired with any mathematically compatible upper limit. In someembodiments, the formation treatment composition of the presentdisclosure may incorporate an acid in an aqueous solution. In someembodiments, the omniphobic fluorochemical may be combined with suitableinorganic or organic acids or acid-producing systems as a means oftailoring the acid reactivity with the rock matrix.

The aqueous solution of one or more embodiments includes water. Thewater may be distilled water, deionized water, tap water, fresh waterfrom surface or subsurface sources, production water, formation water,natural and synthetic brines, brackish water, natural and synthetic seawater, potable water, non-potable water, other waters, and combinationsthereof, that are suitable for use in a wellbore environment. In one ormore embodiments, the water used may naturally contain contaminants,such as salts, ions, minerals, organics, and combinations thereof, aslong as the contaminants do not interfere with the formation of anomniphobic fluorochemical barrier.

In one or more particular embodiments, an acid may be present in thetreatment composition. The acid may include an inorganic acid, anorganic acid, or both. The inorganic acid may include, but is notlimited to, hydrochloric acid, nitric acid, hydrofluoric acid,hydrobromic acid, perchloric acid, fluoroboric acid, or derivatives, andmixtures thereof. The organic acid may include, but is not limited to,methanesulfonic acid, formic acid, acetic acid, citric acid, lacticacid, sulfamic acid, chloroacetic acid, or derivatives, and mixturesthereof. In one or more particular embodiments, the acid may be selectedfrom the group consisting of hydrochloric acid, methanesulfonic acid,other organic acids, or combinations thereof.

Acid-producing systems may include, but are not limited to, esters,nitriles, lactones, anhydrides, orthoesters, polyesters orpolyorthoesters. The acid-producing systems may include esters of shortchain carboxylic acids, including, but not limited to, acetic and formicacid, and esters of hydroxycarboxylic acids, including, but not limitedto, glycolic and lactic acid. These acid-producing systems may providethe corresponding acids when hydrolyzed in the presence of water.

The acid may be present in in the treatment composition in an amounthaving a lower limit of one of 1 wt %, 2.5 wt %, 5 wt %, 7.5 wt %, 10 wt%, 15 wt %, 20 wt %, 25 wt %, 30 wt %, 35 wt %, 40 wt %, 45 wt %, 50,and 60 wt % wt % and an upper limit of one of 10 wt %, 15 wt %, 17.5 wt%, 20 wt %, 25 wt %, 30 wt %, 35 wt %, 50 wt %, 60 wt % and 70 wt %,where any lower limit may be paired with any mathematically compatibleupper limit. In one or more particular embodiments, the acid may bepresent in the treatment composition at a concentration in a range offrom about 5 wt % to about 35 wt %, such as from about 7 wt % to about32 wt %, from about 10 wt % to about 30 wt %, and from about 15 wt % toabout 28 wt %, based on the weight of the treatment composition.

The formation treatment composition described in one or more embodimentsof the present disclosure may optionally include one or more additives,for example, to improve the compatibility of the fluids described inthis application with other fluids (for instance, formation fluids) thatmay be present in the well bore. Suitable additives may be used inliquid or powder form. Examples of such additional additives include,but are not limited to, pH-adjusting agents, pH-buffers, oxidizingagents, enzymes, lost circulation materials, scale inhibitors,surfactants, clay stabilizers, corrosion inhibitors, paraffininhibitors, asphaltene inhibitors, penetrating agents, clay controladditives, iron control additives, reducers, oxygen scavengers, sulfidescavengers, emulsifiers, foamers, gases, derivatives thereof, andcombinations thereof.

Where used, additives are present in the fluids in an amount sufficientto prevent incompatibility with formation fluids or well bore fluids. Insome embodiments, additives may be in a range of from about 0.01 vol %to about 10 vol % (volume percentage) of the formation treatmentcomposition. In some embodiments, where powdered additives are used, theadditives may be present in an amount in the range of from about 0.001wt % to about 10 wt % of the total formation treatment composition.Examples of surfactants may include LOSURF259™ nonionic non-emulsifier,LOSURF300™ nonionic surfactant, LOSURF-357™ nonionic surfactant,LOSURF-400™ surfactant, and NEA-96M™ Surfactant.

In some embodiments, the formation treatment composition may optionallyinclude a foamer. Examples of foamers include, but are not limited to,surfactants, for example, water-soluble, nonionic, anionic, cationic,and amphoteric surfactants; carbohydrates, for example, polysaccharides,cellulosic derivatives, guar, guar derivatives, xanthan, carrageenan,starch polymers, gums, polyacrylamides, polyacrylates, betaine-basedsurfactants, viscoelastic surfactants, natural and synthetic clays;polymeric surfactants, for example, partially hydrolyzed polyvinylacetate; partially hydrolyzed modified polyvinyl acetate; block orcopolymers of polyethane, polypropane, polybutane and polypentane;proteins; partially hydrolyzed polyvinyl acetate, polyacrylate, andderivatives of polyacrylates; polyvinyl pyrrolidone and derivativesthereof; N₂; CO; CO₂; air; and natural gas; and combinations thereof.

In some embodiments, mutual solvents may be employed. Mutual solventsmay help keep other additives in solution. Suitable mutual solvents mayinclude, but are not limited to, Halliburton's MUSOL® Mutual Solvent,MUSOL® A Mutual Solvent, MUSOL® E Mutual Solvent, ethylene glycolmonobutyl ether, propylene glycol monobutyl ether, water, methanol,isopropyl alcohol, alcohol ethers, aromatic solvents, otherhydrocarbons, mineral oils, paraffins, derivatives thereof, andcombinations thereof. Other suitable solvents may also be used. If used,the mutual solvent may be included in a range of from about 1 vol % toabout 20 vol %, and in certain embodiments in a range of from about 5vol % to about 10 vol % based on the of the total volume of theformation treatment composition.

In some embodiments, the formation treatment composition may optionallyinclude one or more viscosifying agents. In some embodiments, theformation treatment composition may be viscosified by a polymer system,for instance, a cross-linked polymer system, where the crosslinkercomprises zirconium or ferric metal clusters.

In some embodiments, the formation treatment composition may optionallyinclude an emulsion. The emulsion may include nonionic surfactants, suchas sorbitan esters, AF-61™ Emulsifer, and AF-70™ Emulsifier (HalliburtonEnergy Services, Oklahoma). In some embodiments, a surfactant is an oilexternal surfactant, which may include AF-61™ Emulsifer and AF-70™Emulsifier. For water external emulsions, exemplary surfactants includeSEM-7™ Emulsifier, WS-36™ Dispersant, and WS-44™ Emulsifier. Optionalsurfactants may be included in an amount ranging from about 0.1 vol %(volume percent) to about 3 vol % based on the total volume of solutionis sufficient. In some embodiments, the emulsion can be mixed at thesurface of the reservoir, or prior to reservoir treatment and thenpumped downhole as described above. In some embodiments, the componentscan be pumped downhole and then mixed in coiled tubing, bullheading, orproduction tubing as described above.

In some embodiments, the formation treatment composition may optionallyinclude one or more gelling agents. Any gelling agent suitable for usein subterranean applications may be used in the formation treatmentcomposition of the present disclosure, including, but not limited to,natural biopolymers, synthetic polymers, cross-linked gelling agents,and viscoelastic surfactants. Guar and xanthan are examples of suitablegelling agents. A variety of gelling agents may be used, includinghydratable polymers that contain one or more functional groups such ashydroxyl, carboxyl, sulfate, sulfonate, amino or amide groups. Suitablegelling agents may comprise polysaccharides, biopolymers, syntheticpolymers, and a combination thereof. Examples of suitable polymersinclude, but are not limited to, guar gum and derivatives thereof, suchas hydroxypropyl guar and carboxymethylhydroxypropyl guar; cellulosederivatives, such as hydroxyethyl cellulose; locust bean gum; tara;konjak; tamarind; starch; cellulose; karaya; diutan; scleroglucan;wellan; gellan; xanthan; tragacanth; carrageenan; derivatives thereof;and combinations thereof of one or more of such polymers. Additionally,synthetic polymers and copolymers may be used. Examples of suchsynthetic polymers include, but are not limited to, polyacrylate,polymethacrylate, polyacrylamide, polyvinyl alcohol, andpolyvinylpyrrolidone. Commonly used synthetic polymer acid-gellingagents may include polymers and copolymers having various ratios ofacrylic, acrylamide, acrylamidomethylpropane sulfonic acid, quaternizeddimethylaminoethylacrylate, and quaternizeddimethylaminoethylmethacrylate.

In other embodiments, the gelling agent molecule may be depolymerized.The term “depolymerized” generally refers to a decrease in the molecularweight of the gelling agent molecule. The gelling agent may includeoxidizers, encapsulated oxidizers, or enzyme breakers, such as sodiumpersulfate, potassium persulfate, ammonium persulfate, magnesiumperoxide, sodium chlorite, sodium bromate, alpha and beta amylases,amyloglucosidase, invertase, maltase, cellulose, hemicellulose, and thelike. If used, a gelling agent may be present in the acid-generatingfluids of the formation treatment composition in an amount in the rangeof from about 0.01 wt % to about 5 wt % of the base fluid.

To combat possible perceived problems associated with polymeric gellingagents, some surfactants have been used as gelling agents. It is wellunderstood that when mixed with a fluid in a concentration greater thanthe critical micelle concentration the molecules (or ions) ofsurfactants may associate to form micelles. These micelles may function,among other purposes, to stabilize emulsions, break emulsions, stabilizefoam, change the wettability of a surface, solubilize certain materials,and reduce surface tension. When used as a gelling agent, the molecules(or ions) of the surfactants used associate to form micelles of acertain micellar structure (e.g., rodlike, wormlike, or vesicles whichare referred to here as “viscosifying micelles”) that, under certainconditions (e.g., concentration or ionic strength of the fluid) arecapable of, inter alia, imparting increased viscosity to a particularfluid and forming a gel. Certain viscosifying micelles may impartincreased viscosity to a fluid such that the fluid exhibits viscoelasticbehavior (e.g., shear thinning properties) due, at least in part, to theassociation of the surfactant molecules. Moreover, because theviscosifying micelles may be sensitive to pH and hydrocarbons, theviscosity of these viscoelastic surfactant fluids may be reduced afterintroduction into the subterranean formation without the need forcertain types of gel breakers (e.g., oxidizers).

A particular surfactant that may be useful is a methyl ester sulfonate(MES) surfactant. Suitable MES surfactants include, but are not limitedto, methyl ester sulfonate surfactants having the formulaRCH(SO₃M)CO₂CH₃, where R is an alkyl chain of about C₁₀-C₃₀. This mayallow a substantial portion of the viscoelastic surfactant fluids to beproduced back from the formation without the need for expensive remedialtreatments. If used, these surfactants may be used in an amount rangingfrom about 0.1 gpt to about 100 gpt of the formation treatmentcomposition.

While optional, at least a portion of the gelling agent included in theformation treatment composition may be cross linked by a reactioncomprising a cross linking agent, for example, to further increaseviscosity. Cross-linking agents typically comprise at least one metalion that is capable of cross-linking gelling agent molecules. Variouscross-linking agents may be suitable; formation treatment compositionsare not limited by ligand choice on the cross-linking agent. Examples ofsuitable cross linking agents may include zirconium compounds (such as,zirconium lactate, zirconium lactate triethanolamine, zirconiumcarbonate, zirconium acetylacetonate, zirconium maleate, zirconiumcitrate, zirconium oxychloride, and zirconium diisopropylamine lactate);titanium compounds (such as, titanium lactate, titanium maleate,titanium citrate, titanium ammonium lactate, titanium triethanolamine,and titanium acetylacetonate); aluminum compounds (such as, aluminumlactate or aluminum citrate); borate compounds (such as, sodiumtetraborate, boric acid, disodium octaborate tetrahydrate, sodiumdiborate, ulexite, and colemanite); antimony compounds; chromiumcompounds; iron compounds; copper compounds; zinc compounds; or acombination thereof. An example of a suitable commercially availablezirconium-based cross-linking agent is CL24™ cross-linker fromHalliburton Energy Services, Inc., Duncan, Oklahoma. An example of asuitable commercially available titanium-based cross-linking agent isCL39™ cross linker from Halliburton Energy Services, Inc., DuncanOklahoma. An example of a suitable borate-based cross-linking agent iscommercially available as CL-22™ delayed borate cross linker fromHalliburton Energy Services, Inc., Duncan, Oklahoma. Divalent ions alsomay be used, for example, calcium chloride and magnesium oxide. Anexample of a suitable divalent ion cross linking agent is commerciallyavailable as CL30™ from Halliburton Energy Services, Inc., Duncan,Oklahoma.

Another example of a suitable cross-linking agent is CL-15, fromHalliburton Energy Services, Inc., Duncan Oklahoma. Where present, thecross-linking agent generally may be included in the treatmentcomposition in an amount sufficient, among other things, to provide thedesired degree of cross linking. In some embodiments, the cross-linkingagent may be present in the formation treatment composition in an amountin the range of from about 0.01 wt % to about 5 wt % of the total weightof the formation treatment composition. Buffering compounds may be usedif desired, for example, to delay or control the cross-linking reaction.These may include, but are not limited to, glycolic acid, carbonates,bicarbonates, acetates, and phosphates. In some embodiments, if agelling agent (for instance, a cross linked gelling agent) is used, thena suitable breaker may be advisable depending on the gelling agent andits interaction with the acid-generating compound, the generated acid,and the well bore conditions. A breaker may be advisable to ultimatelyreduce the viscosity of the formation treatment composition. Any breakersuitable for the subterranean formation and the gelling agent may beused. The amount of a breaker to include will depend, inter alia, on theamount of gelling agent present in the formation treatment composition.Other considerations regarding the breaker are known to one skilled inthe art.

In one or more embodiments, the formation treatment composition mayoptionally include one or more bactericides. Bactericides protect boththe subterranean formation as well as the fluid from attack by bacteria.Such attacks may be problematic because they may reduce the viscosity ofthe fluid, resulting in poorer performance, for example. Bacteria mayalso cause plugging by bacterial slime production and can turn the oilin the formation sour. Any bactericides known in the art are suitable.An artisan of ordinary skill with the benefit of this disclosure will beable to identify a suitable bactericide and the proper concentration ofsuch bactericide for a given application. Where used, such bactericidesmay be present in an amount sufficient to destroy all bacteria that maybe present. Examples of suitable bactericides include but are notlimited to 2,2-dibromo-3-nitrilopropionamide and2-bromo-2-nitro-1,3-propanediol. In one embodiment, the bactericides maybe present in the formation treatment composition in an amount in therange of from about 0.001 wt % to about 0.003 wt % based on the totalweight of the formation treatment composition. Another example of asuitable bactericide is a solution of sodium hypochlorite. In certainembodiments, such bactericides may be present in the formation treatmentcomposition in an amount in the range of from about 0.01 vol % to about0.1 vol % based on the total volume of the formation treatmentcomposition.

Method of Making a Treatment Composition

One or more embodiments of the present disclosure relate to a method forpreparing a formation treatment composition that may include anomniphobic fluorochemical, an acid, or combinations thereof. The methodincludes preparing the formation treatment composition by mixing theomniphobic fluorochemical with an acid in a solution and introducing theformation treatment composition into a wellbore such that that theformation treatment composition contacts the formation. In someembodiments, the omniphobic fluorochemical and the acid may each be inan aqueous solution and combined prior to a formation treatment.

In some embodiments, the omniphobic fluorochemical and an acid may beadded, separately or together, to an aqueous medium of the formationtreatment composition so that the omniphobic fluorochemical is in anamount sub-stoichiometric compared to the acid. In some embodiments, theomniphobic fluorochemical may be added with an acidic aqueous solutionin the formation treatment composition so that the omniphobicfluorochemical is present in the formation treatment composition at aconcentration of less than 100 gpt (gallons per 1000 gallons). In someembodiments, the formation treatment composition may be added toformations having fractures extending from tens to several hundreds offeet.

In one or more particular embodiments, the treatment may include apre-flush fluid prior to introducing the treatment composition. Thepre-flush fluid may be prepared by adding an omniphobic fluorochemicalto a solvent. The treatment composition may include an acidic fluidprepared by dissolving an acid in an aqueous fluid. The pre-flush fluidof one or more embodiments may include an omniphobic fluorochemical in ahydrocarbon solvent. In one or more particular embodiments, thepre-flush fluid may include an aqueous solution of the omniphobicfluorochemical. The omniphobic fluorochemical of such embodiments may bewater-soluble.

Method of Attenuating Acid Reactivity

One or more embodiments of the present disclosure relate to a method forattenuating the reactivity of acid with a formation using a formationtreatment composition which includes an omniphobic fluorochemical, anacid, or a combination thereof. As described above, a mixture includingthe aqueous solution of the acid and the aqueous solution of theomniphobic fluorochemical forms the formation treatment composition.

The method of attenuating acid reactivity with a formation treatmentcomposition of one or more embodiments includes introducing theformation treatment composition into a wellbore such that that theformation treatment composition contacts a rock surface of theformation. In one or more particular embodiments, the formation (or“rock” or “rock matrix”) includes a carbonate formation, such as acarbonate rock. In such embodiments, a carbonate rock may includelimestone (or calcium carbonate, CaCO₃), dolomite (calcium magnesiumcarbonate, CaMg(CO₃)₂), or both. Embodiments that include dolomite andlimestone in the carbonate rock may be in any ratio.

In some embodiments, the step of contacting the formation includesintroducing the formation treatment composition into the formation viacoiled tubing or bullheading in a production tube. In one or moreembodiments, a method of attenuating acid reactivity may includeintroducing an aqueous solution of the omniphobic fluorochemicalsolution and an aqueous solution of the acid into the formation inseparate stages, optionally via the same or different tubings, such asthe same or different coiled tubings, and allowing the aqueous fluids tomix within the formation to form the formation treatment composition.The two aqueous solutions are mixed in situ within the tubing, withinthe formation, or within the area around the wellbore.

The omniphobic fluorochemical may include a hydrophilic head-group and ahydrophobic tail-group as described above. Upon contact with theformation, the omniphobic fluorochemical preferentially adsorbs onto theformation surface, creating a temporary barrier between the acid of theformation treatment composition and the formation surface, controllingacid diffusion to the formation surface, and hence, retarding the acidreactivity. The omniphobic fluorochemical may adhere to the formationsurface via surface adsorption resulting from the coordination of thehydrophilic head groups with the formation surface. The tail groups aretherefore directed outward from the formation surface. The tail groupsinduce a hydrophobic or omniphobic character in the vicinity of theformation surface. This hydrophobic or omniphobic character hindersaccess of the acidic component of the formation treatment composition tothe formation surface. In some embodiments, the omniphobicfluorochemical may generate foam, which may be responsible for theattenuation behavior as the presence of foam in the vicinity of theformation surface will provide a temporary barrier between the acid andthe rock matrix.

The acidic component of the formation treatment composition may flowdeeper into the formation, where it may encounter a portion of formationsurface not hindered by the barrier created by the omniphobicfluorochemical contacting the formation surface. The acid may theninteract with the deeper formation surface, including reacting with itat an increased penetration depth. The omniphobic fluorochemical barrierof one or more embodiments may mitigate, such that it attenuates areaction between the acid of formation treatment composition and therock surface. In such embodiments, the omniphobic fluorochemical mayprovide partial attenuation of the reaction between the formationsurface and the acid.

In one or more particular embodiments, a method of attenuating acidreactivity may include introducing a pre-flush fluid. The formationtreatment of some embodiments may include a pre-flush fluid. Thepre-flush fluid may include an omniphobic fluorochemical and a solvent.In such embodiments, an acidic fluid including an acid and a secondsolvent may then be employed for formation treatment.

The solvent of the pre-flush fluid of one or more embodiments may be ahydrocarbon solvent, an alcohol-based solvent, an aqueous fluid, orcombinations thereof. In one or more particular embodiments, thealcohol-based solvent may be methanol and/or ethanol. The aqueous fluidmay include a water-based fluid. In some embodiments, the aqueous fluidmay be a gelled fluid, a crosslinked fluid, an emulsified fluid, aviscoelastic (VES) fluid system, or combinations thereof. In someembodiments, the introducing the pre-flush fluid may be performed priorto introducing an acidic fluid, such that the pre-flush fluid contacts aformation surface for a period of time.

In some embodiments, the pre-flush fluid is in contact with theformation for a time ranging from about 1 hour to about 12 hours. Theformation treatment composition or the pre-flush fluid may be in contactwith a formation for a period of time with a lower limit of one of 1, 2,2.5, 4, 5, 7.5, 8, and 10 hours, and an upper limit of one of 2, 2.5, 3,4, 5, 6, 7, 8, 10, 11, and 12 hours, where any lower limit may be pairedwith any mathematically compatible upper limit.

The step of contacting the formation for a period of time with thepre-flush fluid may further include contacting the omniphobicfluorochemical of the formation treatment composition with the rock ofthe formation, or contacting the omniphobic fluorochemical of thepre-flush fluid with the rock of the formation. In such embodiments, thecontacting the rock of the formation further includes creating anomniphobic fluorochemical barrier on the rock surface.

An acidic fluid as described above, which includes an acid in an aqueousfluid, is then injected into the reservoir. As described above, theacidic fluid may flow deeper into the formation to encounter a portionof formation surface not hindered by the barrier created by theomniphobic fluorochemical contacting the formation surface. The acid ofthe aqueous fluid may then interact with the deeper formation surface.In such embodiments, the omniphobic fluorochemical barrier mitigates areaction between the acid of the second fluid and the rock surface,thereby attenuating a reaction between the rock and the acid.

In some embodiments, a method of attenuating acid reactivity may includeintroducing a formation treatment composition prior to introducing anacidic solution. In such embodiments, the steps of injecting theformation treatment composition prior to injecting the acidic solutionmay optionally be repeated.

The acidic fluid of one or more embodiments may be introduced incoordination or combination with supercritical carbon dioxide ornitrogen. In such embodiments, the introduction of the acidic fluid incombination with nitrogen may include the omniphobic fluorochemical ofone or more embodiments, thereby forming an energized treatment fluid.

The omniphobic fluorochemical barrier of one or more embodiments mayalter the wettability of the rock surface. In such embodiments, theomnipobic fluorochemical barrier may change the wettability of the rocksurface to repel aqueous solutions and hydrocarbon solutions. In one ormore embodiments, creating the omniphobic fluorochemical barrier on therock surface includes increasing a contact angle between the injectedformation treatment composition and the rock surface, thereby providinga decreased liquid wetting of the rock surface.

The wettability of the barrier on the rock surface may be measured bycontact angle measurements. The contact angle is the angle formed by aliquid at the three-phase boundary where a liquid, a gas, and solidintersect. In one or more particular embodiments, the omniphobicfluorochemical barrier may have a contact angle between the injectedformation treatment composition, or the injected pre-flush fluid, andthe rock surface with a lower limit of 70 degrees)(°, 80°, 90°, 100°,110°, 115°, 120°, 130°, 140°, 150°, 155°, and 165°, and an upper limitof 110°, 120°, 130°, 145°, 150°, 155°, 160°, 165°, 170°, and 180° whereany lower limit may be paired with any mathematically compatible upperlimit. In such embodiments, the omniphobic fluorochemical barrier mayhave a contact angle of at least 110° or at least 120°.

The method of attenuating acid reactivity of one or more embodiments mayfurther include producing hydrocarbons from the carbonate formation. Theformation (e.g., a carbonate formation or a carbonate rock) may includehighly conductive channel networks formed by the retarded action of theacid solution within the formation.

The method of attenuating acid reactivity of one or more particularembodiments described above may be performed repeatedly. In suchembodiments, the method of attenuating acid reactivity may includeinjecting the pre-flush fluid, the acidic fluid, the formation treatmentcomposition, or combinations thereof. In such embodiments, the pre-flushfluid, the acidic fluid, the formation treatment composition, orcombinations thereof may be injected in a pulse mode. In one or moreparticular embodiments, the formation treatment composition includingthe acid and the omniphobic fluorochemical may be injected followed byan acidic solution.

EXAMPLES

The following examples are merely illustrative and should not beinterpreted as limiting the scope of the present disclosure.

Fluorinated chemicals employed in the following studies were WS1200®(3M) and NW100® (10 vol % in water, Verdechem). Fluorosilanes includingaqueous Dynasylan® F 8815, Dynasylan® F 8263 in propanol solvent, andDynasylan® F 9896 in ethanol solvent were obtained from EvonikIndustries (New Jersey). American Chemical Society (ACS) gradhydrochloric acid (HCl) was obtained from VWR. Deionized water wasobtained from a water purification system with an 18.2 mΩ/cm (milliOhmsper centimeter) resistivity.

Example 1. Contact Angle Measurement Studies Between Carbonate and Water

NW100® was diluted with water to obtain final concentrations of 50 gpt,40 gpt, 30 gpt, 20, gpt, 10 gpt, 5 gpt, and 2 gpt. The contact angle ofwater of an untreated and treated marble surface was measured fordifferent solutions of NW100®. A ramé-hart Contact Angle Goniometer forcontact angle measurements. In such measurements, a contact angle can bemeasured by producing a drop of liquid on a solid surface. The angleformed between the solid/liquid interface and the liquid/vapor interfaceis referred to as the contact angle. The most common method formeasurement involves evaluating the profile of the drop of liquid andtwo-dimensionally measuring the angle formed between the solid and thedrop of liquid profile with the vertex at the three-phase line.

The different solutions were formulated with increasing concentrationsof NW100® from 0 to 50 gpt. FIG. 1 is a graph demonstrating resultsobtained for water contact angle measurements at varying concentrationsof NW100 ®. In FIG. 1 , it is noted that even at relatively lowconcentrations, such as 2 gpt, the NW100® was altered the contact anglefrom 40 degrees (water wet) to 120 degrees (non-water wet).

Example 2. Core-Plug Dissolution Experiments

The objective of this study was to access the dissolution profile for aseries of acid packages under analogous testing conditions. Theparameters included ambient pressure and temperature, a standard fluidvolume of 100 mL (milliliters) and an exposure time of 5 minutes. Theacid formulations were prepared by adding up to 20 gpt of selectfluorinated surfactants to HCl (up to 28 wt %). The fluorinatedsurfactants included in these studies were WS1200® (3M) and NW100®(Verdechem).

In a typical experiment, the following steps were performed. HomogenousIndiana limestone core samples having a permeability between 4-8 mD(milliDarcy) were cut to diameter and length of 1.5 inches diameter by0.5 inch length. One core sample was used for each individual test.Cores were then dried in an oven at 248° F. overnight. Each of the driedcores were then saturated in deionized water under vacuum for 12 to 24hours. The dry and saturated weight for the pre-treated cores wererecorded and porosity was calculated. Acidified solutions were preparedaccording to formulation details listed in Table 1.

Each core sample was subjected to deionized water (DI H₂O) saturation.Each saturated core was then transferred to a 250 mL (milliliter) beakercontaining 100 mL of each acid formulation. For each experiment, thecore sample was placed vertically in the solution for a duration of 5minutes under ambient temperature and pressure conditions. The samplewas promptly removed and submerged in DI-H₂O to stop the reaction.Digital photos were taken of the cores before and after acidizing.

With respect to Formulation 3, a dry core sample was transferred tobeaker containing NW100® (2 gpt in water) and allowed to pre-soak for 24h. The sample was then removed and placed directly into a 250 mL beakercontaining 100 mL of Formulation 3. As mentioned above, the core samplewas placed vertically in the solution for a duration of 5 minutes underambient temperature and pressure conditions. The sample was promptlyremoved and submerged in DI H₂O to stop the reaction. Digital photoswere taken of the cores before and after acidizing.

The weight of each of the saturated acidized core samples was measuredfor both the dry and saturated core sample. The percent of the weightloss for each core was calculated and compared. Additionally, for eachtest, the amount of dissolved calcite (CaCO₃) was calculated usingInductively Coupled Plasma Optical Emission Spectrometry (ICP-OES)measurements by determining the calcium concentration detected from analiquot of the reaction.

TABLE 1 Calculated weight loss of Indiana limestone core samplespost-acidizing. Additive Calcite HCl Additive Concentration DissolvedFormulation (wt %) Name (gpt) (%) 1 15 N/A 0 38.7 2 28 N/A 0 57 3 15NW100 ® 2 5.81 (sample pre- coated) 4 15 WS1200 ® 20 3.6 5 15 WS1200 ®60 3.1 6 15 WS1200 ® 2.5 9.9 7 15 WS1200 ® 10 4.2 8 28 WS1200 ® 2.5 15.79 28 WS1200 ® 10 8.1

The calculated weight loss of Indiana limestone core samples,post-acidizing, for the acid formulations containing 15 and 28 wt % HClin the absence of the fluorochemicals NW100® and WS1200® indicatedrelatively high percentages of calcite dissolved. In contrast, thepresence of the noted fluorochemical additive shows that the substantialdecrease in the dissolution of rock in acid. For example, formulations3-7 and formulation 9 demonstrate the suitability of the fluorochemicaladditives to attenuate acid reactivity. In addition, results fromstudies with Formulation 8 similarly indicate a notable decrease in acidreactivity with calcite with slightly elevated calcite removalpercentages. This is presumably a result of the increased acid tofluorochemical ratio of the formulation.

Additional core dissolution studies were performed with fluorochemicaladditives 8815, 8263, and 9896 each in water with 15 wt % HCl. Indianalimestone core samples and dissolution studies were prepared accordingto the procedures described above. Results of these studies are providedin Table 2.

TABLE 2 Calculated weight loss of Indiana limestone core samplespost-acidizing. Additive Calcite HCl Additive Concentration Dissolved(wt %) Name (Vol %) (%) 15 No Additive 0 43 15 Dynasylan ® 10 37.3 8815in Water 15 Dynasylan ® 10 35.9 8263 in Propanol 15 Dynasylan ® 10 47.49896 in Ethanol

Results from Table 2 indicate the low acid attenuating functionality offluorochemical additives Dynasylan® 8815, Dynasylan® 8263, Dynasylan®9896. In contrast to results highlighted in Table 1, results of Table 2indicate a low propensity to prevent calcite dissolution. Notably,Dynasylan® 8815, Dynasylan® 8263, and Dynasylan® 9896 are fluorinatedsilanes. In effect, comparative results of Table 1 and Table 2 bringattention to the fact that not all fluorinated chemicals can be used toattenuate acidic reactivity of carbonate rock.

Example 3. High Temperature/High Pressure Coreflow Studies

Core preparation procedures were performed as follows. Indiana limestonecalcite core samples having a porosity ranging from 14.3 to 16.3 vol %(volume percent) obtained from a local supplier in Texas and wereselected for this study. The absolute permeability for each deionizedwater saturated core sample was measured in a horizontal fashion using ahigh temperature, high pressure (HT/HP) coreflood apparatus equippedwith a 12 inch coreholder. The permeability of core samples wascalculated by flowing deionized water through the core sample at variousflow rates, such as ranging flow rates from 0.5 to 4 cm³/min(centimeters cubed per minute) until the flow stabilized. For each flowrate, the average differential pressure across the core (DP) wasrecorded and applied to Darcy's equation to determine the initialpermeability.

Coreflow experiments are commonly performed in the oil and gas industryto evaluate and benchmark the performance of an assortment of oilfieldreservoir stimulation fluids, including acid systems. Accordingly, alinear coreflow experiment was performed to validate that acidattenuation behavior observed under static conditions, ambienttemperature, and ambient pressure applied to reservoir conditions. Inthis regard, conditions were 300° F. and 3000 psi. Formulationscontaining 28 wt. % HCl and 10 gpt of WS1200® were selected asproof-of-concept for this study.

For acidizing applications, the volume of acid required to dissolve apath in the core plug, i.e. from the inlet to the outlet of the coresample, is one indication of success at the lab-scale. This value iscommonly referred to as pore volume to breakthrough (PVBT). Acid systemshaving higher acid-rock reactivity will be associated with higher PVBTvalues under analogous testing conditions and vice versa. Thus, lowerPVBT values are desired because the expectation is that at thefield-scale the result will correlate with increased stimulation of thetreated zone. This result is driven by the fact that live acid canpenetrate deeper into the reservoir, and thereby, increase the relativepermeability for oil and gas to be produced. As shown in FIG. 2 , themeasured pressure drop across the core sample during acid injectionindicates desired acid breakthrough.

Guided by the promising attenuation results obtained under ambientconditions shown in FIG. 2 , it was anticipated that the instantformulation tested would require less acid to achieve breakthrough ascompared to 28 wt % HCl in the absence of surfactant. Table 3 provides asummary of coreflood data collected for 12-inch outcrop Indianalimestone core samples treated with different acid systems at atemperature, pressure and flow rate of 300° F., 3000 psi, and 5 cm³/min,respectively.

TABLE 3 Summary of coreflood data collected for 12-inch outcrop Indianalimestone core samples. Core Core Length Diameter Fluid ID PV_(BT)(inch) (inch) 28 wt % HCl + 0.25 12 1.5 10 gpt WS 1200 ® 28 wt % HCl1.1  12 1.5 26 wt % Emulsified Acid 0.55 12 1.5

As shown in Table 3, the acid volume needed to achieve breakthrough wasreduced by 75% from the addition of WS1200® to an acidic solutionincluding 28 wt % HCl. Even when compared to 26 wt. % HCl of anemulsified acid, the system with fluorochemical WS1200 demonstratedaround 50% reduction in the volume of acid need to achieve breakthrough.In effect, results of Table 3 indicate a 100% improvement in the acidpenetration rate when using the HCl/WS1200® formulation.

The results from these studies detailed above serve as proof-of-conceptto the invention and provide insights as to the role of additiveselection on attenuating the acid-rock reactivity behavior. Althoughonly a few example embodiments have been described in detail above,those skilled in the art will readily appreciate that many modificationsare possible in the example embodiments without materially departingfrom this invention. Accordingly, all such modifications are intended tobe included within the scope of this disclosure as defined in thefollowing claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. § 112(f) for any limitations of any of the claimsherein, except for those in which the claim expressly uses the words‘means for’ together with an associated function.

What is claimed:
 1. A formation treatment composition comprising: anaqueous fluid; an acid; and at least one omniphobic fluorochemicalconfigured to form an omniphobic fluorochemical barrier on a rockmatrix, and wherein the omniphobic fluorochemical barrier is configuredto mitigate a reaction between the rock matrix and the acid, wherein theformation treatment composition comprises the acid in a range from 10 wt% to 70 wt % based on the total weight of the formation treatmentcomposition, wherein the acid is selected from the group consisting ofhydrochloric acid, methanesulfonic acid, and combinations thereof, andwherein the at least one omniphobic fluorochemical is water soluble andis selected from the group consisting of a nonionic acrylic fluorinatedcopolymer, a nonionic fluorinated surfactant, partially fluorinatedacrylic copolymer, a nonionic fluorinated methacrylate polymer, ananionic phosphate fluorinated surfactant, an anionic sulfate fluorinatedsurfactant, and combinations thereof.
 2. The formation treatmentcomposition of claim 1, comprising from 0.1 vol % to 10 vol % of the atleast one omniphobic fluorochemical.
 3. The formation treatmentcomposition of claim 1, wherein the at least one omniphobicfluorochemical is selected from the group consisting of a fluorinatedsurfactant, a fluorinated polymer, and combinations thereof.
 4. Theformation treatment composition of claim 1, wherein the aqueous fluid isselected from the group consisting of a gelled fluid, a crosslinkedfluid, an emulsified fluid, a viscoelastic fluid, and combinationsthereof.
 5. A method of attenuating acid reactivity of a formation rock,the method comprising: injecting a formation treatment composition intoa reservoir, wherein the formation treatment composition comprises asolution of a fluid comprising, at least one omniphobic fluorochemicaland an acid, wherein the at least one omniphobic fluorochemical is watersoluble and is selected from the group consisting of a nonionic acrylicfluorinated copolymer, a nonionic fluorinated surfactant, partiallyfluorinated acrylic copolymer, a nonionic fluorinated methacrylatepolymer, an anionic phosphate fluorinated surfactant, an anionic sulfatefluorinated surfactant, and combinations thereof, wherein the acid isselected from the group consisting of hydrochloric acid, methanesulfonicacid, and combinations thereof, and wherein the formation treatmentcomposition comprises the acid in a range from 10 wt % to 70 wt % basedon the total weight of the formation treatment composition; contactingthe omniphobic fluorochemical of the formation treatment compositionwith the rock, thereby creating an omniphobic fluorochemical barrier ona surface of the formation rock; and mitigating a reaction between theacid of the formation treatment composition and the rock surface,thereby attenuating a reaction between the rock and the acid.
 6. Themethod of claim 5, wherein the reservoir comprises a carbonatereservoir, a carbonate-damaged area of a sandstone reservoir, or acarbonate formation of a rock matrix.
 7. The method of claim 5, whereinthe creating the omniphobic fluorochemical barrier on the rock surfacefurther comprises increasing a contact angle between the injectedformation treatment composition and the rock surface, thereby providinga decreased liquid wetting of the rock surface.
 8. The method of claim7, wherein the creating the omniphobic fluorochemical barrier on therock surface further comprises providing a contact angle of from 70° to160° between the injected formation treatment composition and the rocksurface.
 9. A method of attenuating acid reactivity of a formation rock,the method comprising: injecting a pre-flush fluid into a reservoir,wherein the pre-flush fluid comprises a solution comprising anomniphobic fluorochemical, wherein the at least one omniphobicfluorochemical is water soluble and is selected from the groupconsisting of a nonionic acrylic fluorinated copolymer, a nonionicfluorinated surfactant, partially fluorinated acrylic copolymer, anonionic fluorinated methacrylate polymer, an anionic phosphatefluorinated surfactant, an anionic sulfate fluorinated surfactant, andcombinations thereof; contacting the omniphobic fluorochemical of thepre-flush fluid with a rock surface of the formation, thereby creatingan omniphobic fluorochemical barrier on the rock surface with theomniphobic fluorochemical of the pre-flush fluid; injecting an acidicfluid into the reservoir, wherein the acidic fluid comprises an acid inan aqueous fluid, wherein the acid is selected from the group consistingof hydrochloric acid, methanesulfonic acid, and combinations thereof,and wherein the acidic fluid comprises the acid in a range from 10 wt %to 70 wt % based on the total weight of the acidic fluid; and mitigatinga reaction between the acid of the acidic fluid and the rock surface,thereby attenuating a reaction between the rock and the acid.
 10. Themethod of claim 9, wherein the omniphobic fluorochemical is selectedfrom the group consisting of a fluorinated surfactant, a fluorinatedpolymer, and combinations thereof.
 11. The method of claim 9, whereinthe formation rock comprises a carbonate-damaged area of a sandstonereservoir or a carbonate formation of a rock matrix.
 12. The method ofclaim 9, wherein the creating the omniphobic fluorochemical barrier onthe rock surface further comprises increasing a contact angle betweenthe injected pre-flush fluid and the rock surface, thereby providing adecreased liquid wetting of the rock surface.
 13. The method of claim12, wherein the creating the omniphobic fluorochemical barrier on therock surface further comprises providing a contact angle of from 70° to160° between the injected pre-flush fluid and the rock surface.
 14. Themethod of claim 9, wherein mitigating the reaction further comprises:injecting a formation treatment composition; injecting the acidicsolution; and optionally repeating the injecting the formation treatmentcomposition followed by the acidic solution.
 15. The method of claim 9,further comprising injecting the acidic fluid into the reservoir incombination with supercritical carbon dioxide or nitrogen and afluorochemical.